The recovery of low API gravity or viscous oil from subterranean oil-bearing formations and bitumen from tar sands has generally been difficult. Although some improvement has been realized in the recovery of heavy oils, i.e., oils having an API gravity in the range of 10.degree. to 25.degree. API, little success has been realized in recovering bitumen from tar sands. Bitumen can be regarded as a highly viscous oil having an API gravity in the range of about 5.degree. to about 10 .degree. API and a viscosity in the range of several million centipoise at formation temperature. Bitumens of this kind may be found in essentially unconsolidated sands, generally referred to as tar sands, of which there are extensive deposits in the Athabasca region of Alberta, Canada. While these deposits are estimated to contain about several hundred billion barrels of bitumen, recovery from them, as indicated above, using conventional techniques has not been altogether successful. The reasons for the varying degrees of success arise principally to the fact that the bitumen is extremely viscous at the temperature of the formation, with consequent very low mobility. In addition, the tar sand formations have very low permeability, despite the fact they are unconsolidated.
Because the viscosity of viscous oils decreases markedly with increases in temperature, thermal recovery techniques have been investigated for recovery of bitumen from tar sands. These thermal recovery methods generally include steam injection, hot water injection and in-situ combustion.
Typically, such thermal techniques employ an injection well and a production well transversing the oil-bearing or tar sand formation. In a conventional throughput steam operation, steam is introduced into the formation through an injection well. Upon entering the formation, the heat transferred to the formation by the hot aqueous fluid lowers the viscosity of the formation oil, thereby improving its mobility. In addition, the continued injection of the hot aqueous fluid provides a drive to displace the oil toward the production well from which it is produced.
Thermal techniques employing steam also utilize a single well technique, known as the "huff and puff" method, such as described in U.S. Pat. No. 3,259,186. l In this method, steam is injected via a well in quantities sufficient to heat the subterranean hydrocarbon-bearing formation in the vicinity of the well. The well is then shut-in for a soaking period, after which it is placed on production. After projection has declined, the "huff and puff" method may again be employed on the same well to again stimulate production.
The application of single well schemes employing steam injection and as applied to heavy oils or bitumen is described in U.S. Pat. No. 2,881,838, which utilizes gravity drainage. An improvement of this method is described in a later patent, U.S. Pat. No. 3,155,160, which steam is injected and appropriately timed pressuring and depressuring steps are employed. Where applicable to a field pattern, the "huff and puff" technique may be phased so that numerous wells are on an injection cycle while others are on a production cycle; the cycles may then be reversed.
U.S. Pat. No. 4,257,650 describes a method for recovering high viscosity oils from subsurface formations using steams and an inert gas to pressurize and heat the formation and the oil which it contains. The steam and the inert gas may be injected either simultaneously or sequentially, e.g. steam injection, followed by a soak period, followed by injection of inert gas. Inert gases referred to include helium, methane, carbon dioxide, flue gas, stack gas and other gases which are noncondensable in character and which do not interact either with the formation matrix or the oil or other earth materials contained in the matrix.
Injection of CO.sub.2 with steam during cyclic steam stimulation of heavy oil reservoirs has received attention recently. Carbon dioxide dissolves in the oil easily and causes viscosity reduction, and swelling of the oil which in turn leads to additional oil recovery. Recent simulation studies by Leung, L. C., "Numerical Evaluation of the Effect of Simultaneous Steam and CO.sub.2 Injection on the Recovery of Heavy Oil", J. Pet. Tech., p. 1591 (September 1983), and Redford, D. A., "The Use of Solvents and Gases with Steam in the Recovery of Bitumen from Oil Sands", J. Can. Pet. Tech., p. 45, (January-February 1982), confirm the benefit of CO.sub.2 -steam co-injection into heavy oil reservoirs. The Leung article discloses six cycles of steam stimulation, each with a 40,000 barrel steam (cold water equivalent) slug of steam injected in 40 days, as the base case. Three separate carbon dioxide runs with 200, 400, and 600 SCF carbon dioxide/bbl of steam were used for comparison. A 36% improvement in recovery was observed for the 400 SCF/bbl case, where majority of the incremental oil was obtained in the first three cycles of stimulation. After one cycle, Leung's results show that the optimum carbon dioxide slug size was 400 SCF of carbon dioxide per barrel of steam (cold water equivalent).
In the Redford article cited above, the effect of injecting different solvents and gases including carbon dioxide on recovery of Athabasca bitumen from an oil sand pack penetrated by one injection well and one production well was investigated. The results showed that CO.sub.2 an ethane gas gave improvements in recovery over the other additives, and that the majority of the improvement occurred in the pressure drawdown phases of the experiment. Larger swept volumes resulted from addition of ethane and CO.sub.2 and substantially cooler fluids (non-thermally driven) were produced. An optimum CO.sub.2 -steam ratio was noted to exist at about 35-dm.sup.3 CO.sub.2 /kg steam or 197 SCF/bbl, assuming standard conditions. Undesirable effects of using too much gas were thought to be caused by reduced injectivity, reduced permeability to liquids and an increased tendency towards channeling of steam.
The present invention discloses an improvement in the CO.sub.2 -steam cyclic process in which recovery is maximized by injection of a mixture of carbon dioxide and steam.